Downhole drilling motor and method of use

ABSTRACT

A downhole drilling motor comprises a first elastomer stator molded to an inner surface of a housing in a drillstring where the first elastomer stator has a first number of lobes. A dual purpose, helical shaped hollow member is positioned within the first elastomer stator, where the dual purpose hollow member has a second number of lobes formed on an external surface to form a first rotor. The second number of lobes is one less than the first number of lobes. A second elastomer stator is adhered to an inner surface of the dual purpose helical shaped hollow member, where the second elastomer stator has a second helical shaped cavity with the second number of lobes. A second helical shaped rotor is positioned within the second helical cavity, and has a third number of lobes one less than the second number of lobes.

BACKGROUND OF THE INVENTION

The present disclosure relates generally to the field of drilling wellsand more particularly to downhole drilling motors.

In progressive cavity drilling motors, the motor rpm is directly relatedto the fluid flow rate through the motor. Each motor size is designed toaccommodate a range of fluid flow rates. In some downhole drillingscenarios, there is a need for changing the fluid flow rate and/or therotational speed of bit 150, outside of the design range for thedrilling motor in the drill string. A change out of the motor may berequired with the attendant removal of the drill string from thewellbore. Such changes are costly in terms of rig time.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a schematic diagram of a drilling system;

FIG. 2 shows a diagram of one embodiment of a downhole motor;

FIG. 3A shows one example of fluid flow through a power section of adownhole motor;

FIG. 3B shows another example of fluid flow through a power section of adownhole motor; and

FIG. 4 shows an example of a clutch section of a downhole motor.

DETAILED DESCRIPTION

FIG. 1 shows a schematic diagram of a drilling system 110 having adownhole assembly according to one embodiment of the present disclosure.As shown, the system 110 includes a conventional derrick 111 erected ona derrick floor 112, which supports a rotary table 114 that is rotatedby a prime mover (not shown) at a desired rotational speed. A drillstring 120 that comprises a drill pipe section 122 extends downward fromrotary table 114 into a directional borehole 126. Borehole 126 maytravel in a three-dimensional path. A drill bit 150 is attached to thedownhole end of drill string 120 and disintegrates the geologicalformation 123 when drill bit 150 is rotated. The drill string 120 iscoupled to a drawworks 130 via a kelly joint 121, swivel 128 and line129 through a system of pulleys (not shown). During the drillingoperations, drawworks 130 is operated to control the weight on bit 150and the rate of penetration of drill string 120 into borehole 126. Theoperation of drawworks 130 is well known in the art and is thus notdescribed in detail herein.

During drilling operations a suitable drilling fluid (also referred toin the art as “mud”) 131 from a mud pit 132 is circulated under pressurethrough drill string 120 by a mud pump 134. Drilling fluid 131 passesfrom mud pump 134 into drill string 120 via fluid line 138 and kellyjoint 121. Drilling fluid 131 is discharged at the borehole bottom 151through an opening in drill bit 150. Drilling fluid 131 circulatesuphole through the annular space 127 between drill string 120 andborehole 126 and is discharged into mud pit 132 via a return line 135.Preferably, a variety of sensors (not shown) are appropriately deployedon the surface according to known methods in the art to provideinformation about various drilling-related parameters, such as fluidflow rate, weight on bit, hook load, etc.

In one example embodiment of the present disclosure, a bottom holeassembly (BHA) 159 may comprise a measurement while drilling (MWD)system 158 comprising various sensors to provide information about theformation 123 and downhole drilling parameters. BHA 159 may be coupledbetween the drill bit 150 and the drill pipe 122.

MWD sensors in BHA 159 may include, but are not limited to, a sensorsfor measuring the formation resistivity near the drill bit, a gamma rayinstrument for measuring the formation gamma ray intensity, attitudesensors for determining the inclination and azimuth of the drill string,and pressure sensors for measuring drilling fluid pressure downhole. Theabove-noted sensors may transmit data to a downhole telemetrytransmitter 133, which in turn transmits the data uphole to the surfacecontrol unit 140. In one embodiment a mud pulse telemetry technique maybe used to communicate data from downhole sensors and devices duringdrilling operations. A transducer 143 placed in the mud supply line 138detects the mud pulses responsive to the data transmitted by thedownhole transmitter 133. Transducer 143 generates electrical signals inresponse to the mud pressure variations and transmits such signals to asurface control unit 140. Surface control unit 140 may receive signalsfrom downhole sensors and devices via sensor 143 placed in fluid line138, and processes such signals according to programmed instructionsstored in a memory, or other data storage unit, in data communicationwith surface control unit 140. Surface control unit 140 may displaydesired drilling parameters and other information on a display/monitor142 which may be used by an operator to control the drilling operations.Surface control unit 140 may contain a computer, a memory for storingdata, a data recorder, and other peripherals. Surface control unit 140may also have drilling, log interpretation, and directional modelsstored therein and may process data according to programmedinstructions, and respond to user commands entered through a suitableinput device, such as a keyboard (not shown).

In other embodiments, other telemetry techniques such as electromagneticand/or acoustic techniques, or any other suitable technique known in theart may be utilized for the purposes of this invention. In oneembodiment, hard-wired drill pipe may be used to communicate between thesurface and downhole devices. In one example, combinations of thetechniques described may be used. In one embodiment, a surfacetransmitter receiver 180 communicates with downhole tools using any ofthe transmission techniques described, for example a mud pulse telemetrytechnique. This may enable two-way communication between surface controlunit 140 and the downhole tools described below.

In one embodiment, a downhole drilling motor 190 is included in drillstring 120. Downhole drilling motor 190 may be a fluid driven,progressive cavity drilling motor of the Moineau type that uses drillingfluid to rotate an output shaft that is operatively coupled to drill bit150. These devices are well known in the art and have a helical rotorwithin the cavity of a stator that is connected to the housing of themotor. As the drilling fluid is pumped down through the motor, the fluidrotates the rotor. In some embodiments, the rotation of bit 150 may bethe combination of rotation of drill string 120 and the rotation of themotor shaft. In progressive cavity drilling motors, the motor rpm isdirectly related to the fluid flow rate through the motor. Each motorsize is designed to accommodate a range of fluid flow rates. In somedownhole drilling scenarios, there is a need for changing the fluid flowrate and/or the rotational speed of bit 150, outside of the design rangefor the drilling motor in the drill string. A change out of the motormay be required with the attendant removal of the drill string from thewellbore. Such changes are costly in terms of rig time.

In one embodiment of the present disclosure, see FIG. 2, drilling motor190 comprises a power section 191 that provides two differentrotor/stator combinations. Housing 200 is connected in drill string 122.An elastomer stator 201 is adhered to the inner surface of housing 200.Stator 201 has an inner helically shaped cavity 221 with a first numberN1 of lobes 222 formed along the cavity 221. A dual purpose, helicalshaped, hollow shaft 202 is positioned in the cavity 221. The dualpurpose hollow shaft 202 is formed with a second number N2 of lobes 225on an outer surface to form a first rotor 260, where N2=N1−1. There isan interference seal between the stator lobes 222 of the first stator201 and the lobes 225 of the first rotor 260. When drilling fluid 131Aflows through the passages between the first stator 201 and the firstrotor 260, rotor 260 is forced to rotate relative to first stator 201.Dual purpose hollow shaft 202 may be formed from a metallic material,for example, steel, stainless steel, nickel based alloys, aluminum, andtitanium.

The dual purpose hollow shaft 202 also has a second elastomer stator 203adhered on an inner surface thereof, forming a second cavity 240, wherethe second elastomer stator has a third number N3 of lobes 224 where N3is the same as the number of lobes N2 of the first rotor 260. Similarly,there is a second helical shaped rotor 204 positioned within cavity 240of second stator 203. Second rotor 204 has a fourth number N4 of lobes241 where N4=N3−1. There is an interference seal between the statorlobes 224 of the second stator 203 and the lobes 241 of the second rotor204. When drilling fluid 131B flows through the passages between thesecond stator 203 and the second rotor 204, second rotor 260 is forcedto rotate relative to second stator 203. Second rotor 204 may be formedfrom a metallic material, for example, steel, stainless steel, nickelbased alloys, aluminum, and titanium.

Drilling fluid 131 may be diverted to one of: first flow cavity 221,second flow cavity 240, and both first flow cavity 221 and second flowcavity 240 simultaneously, by a controllable flow selector 210 in theupstream flow passage. Dual purpose hollow shaft 202 has a flexibleconduit 205 that extends form the end of shaft 202 to controllable flowselector 210. Flexible conduit 205 may be coupled to controllable flowselector 210 by a rotating fluid coupling (not shown). This allowsconduit 205 to rotate with shaft 202 while maintaining a flow separationbetween cavities 221 and 240, when desired. A first controller 230 maybe operably connected to flow selector 210 to control the flowselection. In one embodiment, controller 230 may receive instructionsfrom the surface via telemetry from the surface as described above. Inanother example, first controller 230 may receive instructions via aflowable device, for example a radio frequency identification device(RFID) 291 that is inserted in the flow stream. RFID 291 may containinstructions that are transmitted to RFID receiver 290 operablyconnected to first controller 230. RFID's are known in the art and arenot described herein in detail. Controllable flow selector 210 maycomprise internal flow channeling through the use of sliding sleevesand/or actuatable valve elements to suitably divert the fluid flow, asdirected. This capability provides for a wider range of suitable RPM andbit torques over a wider range of fluid flow rates than would bepossible with a single configuration drilling motor.

FIGS. 3A and 3B show axial views of power section 190 with the fluidflowing through the two different flow cavities. FIG. 3A demonstratesflow through first flow cavity 221. Here, the first stator 201 has threelobes 222, and the first rotor 260 has two lobes 225. Fluid flows onlythrough first flow cavity 221, and first rotor 260 rotates with respectto first stator 201 at a rotational speed of RPM1. In FIG. 3B, secondrotor 204 has a single lobe while second stator 203 has 2 lobes. Fluidflows only through second flow cavity 240, and only second rotor 204rotates with respect to second stator 203 at a rotational speed RPM2.Second stator 203 does not rotate with respect to housing 200. Whenfluid flows through both flow cavities 221, 240 each rotor 260, 204rotates with respect to its related stator 201, 203. This causes rotor204 to rotate at an additive speed of RPM3=RPM1+RPM2.

Flexible shafts 206 and 207 couple first rotor 260 and second rotor 204,respectively, through a controllable clutch 220 to output shaft 270 thatis operably coupled to bit 150. In one example, see FIG. 4, controllableclutch 220 comprises a positive engagement clutch, sometimes referred toas a dog clutch. As shown in FIG. 4, flexible shafts 206 and 207 areselectably engaged with engagement collar 403. Engagement collar 403 hasan internal spline 409 that is engageable with spline 415 on the end ofoutput shaft 270. In addition, engagement collar 403 has an externalspline formed on an end closes to power section 191. Flexible shaft 207has an external spline 408 formed thereon. Flexible shaft 206 has aninternal spline 401 formed thereon. By controllably axially movingengagement collar 403, either shaft 206 or shaft 207 may be selectablyengaged with output shaft 270 to drive drill bit 150.

Engagement collar 403 is axially movable by extension and retraction ofyoke 405. Yoke 405 is coupled to linear actuator 406 that is operablyconnected to second controller 407. Controller 407 may be in datacommunication with first controller 290 to coordinate the operation offlow selector 210 and clutch 220 to provide the appropriate output todrill bit 150. Communication may be by any short hop communicationsystem known on the art, for example, acoustic communication, radiofrequency communication, and hard wired communication.

In one embodiment, a conductive coil may be placed around the innercircumference of housing 200 such that the rotation of first rotor 260and/or second rotor 204 induce a voltage that may be used for poweringdownhole controllers 407 and/or 290 and other downhole tools andsensors.

Numerous other modifications, equivalents, and alternatives, will becomeapparent to those skilled in the art once the above disclosure is fullyappreciated. It is intended that the following claims be interpreted toembrace all such modifications, equivalents, and alternatives whereapplicable.

The invention claimed is:
 1. A downhole drilling motor comprising: atubular housing in a drillstring; a first elastomer stator molded to aninner surface of the housing, the first elastomer stator having a firsthelical shaped cavity with a first number of lobes formed therein; adual purpose, helical shaped hollow member positioned within the firstelastomer stator, the dual purpose hollow member having a second numberof lobes formed on an external surface to form a first rotor where thesecond number of lobes of the first rotor is one less than the firstnumber of lobes of the first stator; a second elastomer stator molded toan inner surface of the dual purpose helical shaped hollow member, thesecond elastomer stator having a second helical shaped cavity with thesecond number of lobes; and a second helical shaped rotor positionedwithin the second helical cavity, the second helical shaped rotor havinga third number of lobes wherein the third number of lobes is one lessthan the second number of lobes; a flow selector in a top end of thetubular housing, the flow selector operable to direct drilling fluidthrough at least one of: the first helical shaped cavity; the secondhelical shaped cavity; and both the first helical shaped cavity and thesecond helical shaped cavity; and a first flexible shaft operablyconnected to a lower end of the helical shaped hollow member, and asecond flexible shaft operably connected to a lower end of the helicalshaped second rotor.
 2. The downhole drilling motor of claim 1 furthercomprising a controllable clutch operably coupled to the first flexibleshaft and the second flexible shaft, the clutch actuatable to operablycouple at least one of the first flexible shaft and the second flexibleshaft to an output shaft.
 3. The downhole drilling motor of claim 2further comprising at least one controller operably connected to atleast one of the flow selector and the clutch.
 4. The downhole drillingmotor of claim 3 further comprising at least one radio frequencyidentification device receiver operably coupled to the at least onecontroller.
 5. The downhole drilling motor of claim 1 further comprisinga conductive coil positioned around an inner circumference of thehousing to generate electricity when at least one of the first rotor andthe second rotor rotates.
 6. A method of drilling a well with a downholedrilling motor comprising: positioning a tubular housing in adrillstring; molding a first elastomer stator to an inner surface of thehousing, the first elastomer stator having a first helical shaped cavitywith a first number of lobes formed therein; positioning a dual purpose,helical shaped hollow member within the first elastomer stator, the dualpurpose hollow member having a second number of lobes formed on anexternal surface to form a first rotor where the second number of lobesof the first rotor is one less than the first number of lobes of thefirst stator; molding a second elastomer stator to an inner surface ofthe dual purpose helical shaped hollow member, the second elastomerstator having a second helical shaped cavity with the second number oflobes; positioning a second helical shaped rotor within the secondhelical cavity, the second helical shaped rotor having a third number oflobes wherein the third number of lobes is one less than the secondnumber of lobes; directing a drilling fluid through at least one of: thefirst helical shaped cavity; the second helical shaped cavity; and boththe first helical shaped cavity and the second helical shaped cavity, torotate at least one of the first rotor and the second rotor; andoperably connecting a first flexible shaft to a lower end of the helicalshaped hollow member, and a second flexible shaft to a lower end of thehelical shaped second rotor.
 7. The method of claim 6 further comprisingoperably coupling a controllable clutch to the first flexible shaft andthe second flexible shaft, the clutch actuatable to operably couple atleast one of the first flexible shaft and the second flexible shaft toan output shaft.
 8. The method of claim 7 further comprising operablycontrolling at least one of the flow selector and the clutch.
 9. Themethod of claim 8 further comprising operating at least one of the flowselector and the clutch according to instructions received from at leastone radio frequency identification device transported in the wellbore.10. The method of claim 6 further comprising generating electrical powerfrom a conductive coil positioned around an inner circumference of thehousing when at least one of the first rotor and the second rotorrotates.